In the midst of a year-long battle regarding large-diameter transmission pipelines, Pacific Gas and Electric Co. (PG&E) in late August experienced leaks and a resulting fire in its two-inch diameter plastic distribution main. Then last Thursday California regulators rejected the combination utility’s proposed plan for raising the pressures on some of its transmission pipelines.

As a result of the incident, PG&E now is facing the prospect of stepping up surveying and maintenance of its 40,000-mile distribution pipeline system, in addition to the ongoing close scrutiny the company’s transmission pipelines have been under because of the San Bruno, CA, pipeline explosion. The Aug. 31 incident occurred at a 420-unit townhouse development on the South Bay Peninsula in Cupertino, CA, about 40 miles south of San Francisco in Silicon Valley.

The leaks pertain to a certain type of pre-1973 plastic pipe called “Aldyl-A,” made at the time by DuPont, a PG&E spokesperson told NGI.There were no injuries, but fire consumed one of the town homes. A PG&E crew apparently was on the scene in 20 minutes, pinched off the leak and made repairs, but in surveying the mains serving the rest of the residential complex six other similar cracks were found in tees connecting service pipes to the main distribution pipeline feeding the complex.

PG&E is now planning to check all 1,200 miles of Aldyl-A plastic distribution main that it has in its system dating back to pre-1973. For the Cupertino complex it will replace all 6,000 feet of main and 424 service pipes connecting the individual units, the spokesperson said. PG&E reported the incident to the California Public Utilities Commission (CPUC) and also was contacted by the National Transportation Safety Board (NTSB), which only a couple of days earlier had released its final report on San Bruno (see NGI, Sept. 5).

NTSB was not pursuing anything further on the distribution pipeline incident, said the PG&E spokesperson, who did not know what further action might be forthcoming from the CPUC.

The CPUC last week denied PG&E’s request to have future increases in natural gas pipeline operating pressures done by a regulatory staff executive. As an alternative, the commission unanimously adopted an expedited hearing process during whichit will consider requests to restore the maximum allowable operating pressures (MAOP) in a dozen pipelines in which they have been lowered as a precaution in the wake of last year’s pipeline explosion. A hearing has been set for Sept. 19 to consider PG&E’s request to have the pressure increased in its main transmission pipeline artery from the Arizona-California border (Line 300), according to CPUC Commissioner Mike Florio. The utility hopes to avoid any possible supply shortfalls this winter because of lower pressures in its Line 300.

In the meantime, the CPUC moved full speed ahead with two parallel proceedings related to the San Bruno explosion, as well as to review implementation plans from each of the state’s major gas utility pipeline system operators, including Sempra Energy’s two utilities and Las Vegas, NV-based Southwest Gas Corp.

On July 11 PG&E filed with the state regulatory panel seeking to have CPUC Executive Director Paul Clanon empowered to grant the authorizations to restore the MAOPs in certain transmission pipelines that run through highly populated areas and have characteristics similar to the 30-inch diameter Line 132, which ruptured last year. Thursday’s CPUC action now establishes a public process requiring the utility to “bring forward its senior officers responsible for gas system engineering to present test data and other information supporting its request to restore operating pressure.” Parties in the proceeding will be able to question the PG&E executives and regulators intend the process to require the utility to provide “substantive information” that demonstrates a given pipeline can be operated safely.

In a one-year report to the CPUC, Julie Halligan, deputy director of the CPUC’s Consumer Protection and Safety Division (CPSD), said in the wake of the San Bruno explosion the commission had come to think that PG&E and other operators it regulates did not hold safety as the highest priority “to some degree.” This has led the CPUC to substantially change its rules and approach to ongoing pipeline integrity management programs, Halligan said. Halligan reported on the reduction of pressures on 12 PG&E pipelines and distribution feeder mains for “various reasons,” ranging from lines with characteristics close to Line 132 and incomplete records or failed tests.

“It is important that PG&E justify to this commission and the public that the requested pressure restorations are safe,” Florio said. “That is why we will only allow PG&E to do so through a public and transparent process and after PG&E has presented evidence that it’s the right thing to do.” He said this means in any restoration request PG&E needs to demonstrate it has gone beyond “a pressure test by a contractor.” Each request must include a thorough engineering review.

Separately, the California intra-state gas pipeline operators have submitted implementation plans for pursuing long-term integrity safety management programs for their respective transmission systems. Southwest Gas operates only 15.4 miles of transmission pipelines in California, and under its plan submitted late in August to the CPUC, it plans to replace 7.1 miles for which there are no clear pressure test records available. Sempra’s Southern California Gas Co. (SoCalGas) and San Diego Gas and Electric Co. (SDG&E) operate more than 4,000 miles of transmission pipelines, along with another 97,000 of distribution main and service pipes connected to more than six million meters.

The utility pipeline safety plans were mandated by the CPUC last June, and hearings are expected to be held on all of the utility pipeline plans this fall. Sempra officials have speculated that a final determination by state regulators will most likely not come until last next year.

While Southwest Gas estimates about a $7.6 million cost to its proposed pipeline to replace and automate remote control valve installations, SoCalGas/SDG&E are estimating a $1.68 billion cost over the next four years (2012-15) for its pipeline safety enhancement plan, which is more on the scale of PG&E’s $1.9 billion submittal. The Sempra utilities plan said the gas industry generally is doing a lot of reassessment of pipeline safety standards and best practices. As such, it proposes to work with the CPUC staff to determine the criteria for cases in which neither pressure testing nor replacement are necessary. Instead, SoCalGas and SDG&E are suggesting reductions in operating pressures on given segments of pipeline be implemented.

“Such a standard could potentially reduce pipeline safety implementation costs for customers while providing equivalent safety benefits,” the utilities said in a filing.

Sempra CFO Mark Snell said last Wednesday at the Barclays Capital CEO Energy-Power Conference that the state-mandated pipeline safety project is the company’s largest long-term capital expansion project, spreading over three phases and up to 20 years. The first five years involving 1,200 miles of pipeline (Phase 1A) will be complemented by a second five-year period (Phase 1B) covering 2,400 additional miles of transmission pipeline in less-populated areas (2016-20). Southwest Gas proposes to finish its work by the end of next year, concluding that although its 7.1-mile Victor Valley transmission pipeline system about 100 miles northeast of Los Angeles has been operating safely for 54 years, “it does not meet the CPUC’s pressure testing requirements.” Thus, Southwest is proposing to replace it.

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